The following description includes information that may be useful in understanding the present invention. It is not an admission that any of the information provided herein is prior art or relevant to the presently claimed invention, or that any publication specifically or implicitly referenced is prior art.
The gas processing industry faces challenges in treating natural gas with high acid gas content from unconventional gas fields, such as the coalbed methane, tight sandstones, and methane hydrates. Recently higher gas prices and improved drilling technology have spurred shale gas drilling across the world. However, shale gas also contains significant amounts of H2S and CO2, which must be removed. CO2 is a by-product of shale gas production, and the CO2 level typically steadily increases during a well's productive life, from below 10 mole % to over 30 mole %. In areas where CO2 is used for flooding for enhanced oil recovery, the CO2 level can further increase to over 50%. Moreover, the H2S and CO2 contents of shale gas vary from field to field, posing major challenges to the gas processors in meeting today's emission requirements.
While these plants must operate economically, they must also comply with environmental regulations (e.g., with respect to greenhouse gas and sulfur emissions) and stringent energy efficiency requirements and standards. Removal and compression of the CO2 content for sequestration requires significant amount of capital and operating expenditure, which may render processing the high pressure sour/acid gas field uneconomical.
There are numerous acid gas removal methods that can be used to treat shale gas. For example, a chemical solvent can be used that reacts with acid gas to form a (typically non-covalent) complex with the acid gas. In processes involving a chemical reaction between the acid gas and the solvent, feed gas is typically scrubbed with an alkaline salt solution of a weak inorganic acid, for example, described in U.S. Pat. No. 3,563,695, or with alkaline solutions of organic acids or bases as, for example, described in U.S. Pat. No. 2,177,068. While chemical solvents are suitable to remove acid gases to very low levels, they require large heating and cooling duties which increase proportionally with the partial pressure of acid gases. Hence, the chemical solvent processes are generally uneconomical for treating feed gas with high partial pressure of CO2 (e.g., operating pressure greater than 600 psig with greater than 10% CO2 content).
To overcome these problems, extraction of CO2 using physical solvents is more suitable, because according to Henry's law, the concentration of acid gas in the solvent increases with the acid gas partial pressure. Thus, physical solvent absorption of acid gas is attractive for high acid gas fields and can accommodate variations in CO2 content of feed gases. Moreover, solvent regeneration can be accomplished, by flash regeneration that eliminates the need for heating and so reduces greenhouse gas emissions. However, without external heating, the physical solvent can only be partially regenerated and is therefore generally unsuitable for treatment of sour/acid gases to produce a product that meets pipeline gas specifications (e.g., 1 mol % CO2, 4 ppmv H2S). For example, when conventional physical solvent processes are used for treatment of a feed gas with high H2S content (e.g., ≧100 ppmv), the treated gas typically exceeds H2S limits. To improve the treated gas quality, a sulfur scavenger bed can be used to adsorb additional H2S from the treated gas. However, such scavenger beds may also present problems when the residual H2S content is excessive. For example, large amounts of spent sulfur contaminated beds are often environmentally unacceptable to dispose of and handle.
The physical absorption of acid gases is further dependent upon the solvent's physical properties, pressures, temperatures, and feed gas compositions. For example, methanol may be used as a low-boiling organic physical solvent, as exemplified in U.S. Pat. No. 2,863,527. However, such solvent operates at cryogenic temperature (−80° F.) necessary to enhance absorption and reduce solvent losses. These processes typically require significantly higher electric power to operate the refrigeration unit, which are known to be very high on capital and operating costs.
Other physical solvents are available that can be operated at ambient or mildly refrigerated temperatures (0° F. or lower), including propylene carbonates as described in U.S. Pat. No. 2,926,751 and N-methylpyrrolidone or glycol ethers as described in U.S. Pat. No. 3,505,784. The selection of the physical solvent depends on the application requirements. For example, propylene carbonate is most suitable to remove CO2, but it is not H2S selective and cannot meet low H2S specifications (below 4 ppmv). To some extent, residual H2S from the propylene carbonate unit can be removed using a sulfur scavenger bed as disclosed in WO 2011/041361 “Gas Purification Configurations and Methods”, to meet the requirement, the process is limited to a small quantity of H2S in the feed gas, and is uneconomical for typical sour gas fields.
In further known methods, physical solvents with higher H2S absorption capacity include ethers of polyglycols, and specifically dimethoxytetraethylene glycol as shown in U.S. Pat. No. 2,649,166, or N-substituted morpholine as described in U.S. Pat. No. 3,773,896. While use of the H2S selective solvents can be used to meet today's H2S specification, various difficulties still exist. Among other things, solvent circulation can be excessive and the power consumption and heating requirement can be very high, consequently making the processing uneconomical.
Thus, although various configurations and methods are known to remove acid gases from a feed gas, all or almost all of them suffer from one or more disadvantages. Among other disadvantages, while physical solvents are suitable to treat high pressure sour gases, they all fail to economically treat variable H2S and CO2 contents feed gases, to meet today's environmental requirements on greenhouse gas and the zero emission requirements. Therefore, there is still a need to provide improved methods and configurations for acid gas removal.
This application relates to U.S. patent application Ser. No. 10/511,408, now U.S. Pat. No. 7,637,987; U.S. Pat. No. 7,192,468; and U.S. patent application Ser. No. 13/496,302, which claims priority to U.S. Provisional Pat. App. No. 61/243,969, all of which are incorporated by reference herein. These and all other publications cited herein are incorporated by reference to the same extent as if each individual publication or patent application were specifically and individually indicated to be incorporated by reference. Where a definition or use of a term in an incorporated reference is inconsistent or contrary to the definition of that term provided herein, the definition of that term provided herein applies and the definition of that term in the reference does not apply.